This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
Field of the Invention
The present disclosure relates to the field of hydrocarbon recovery operations. More specifically, the present invention relates to an improved gas compressor used for gas lift operations, and methods for optimizing the injection of compressible fluids into a well to assist in the lift of production fluids to the surface. The invention also relates to real time temperature control for a gas compressor system at a wellbore.
Technology in the Field of the Invention
In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. The drill bit is rotated while force is applied through the drill string and against the rock face of the formation being drilled. After drilling to a predetermined depth, the drill string and bit are removed and the wellbore is lined with a string of casing.
In completing a wellbore, it is common for the drilling company to place a series of casing strings having progressively smaller outer diameters into the wellbore. These include a string of surface casing, at least one intermediate string of casing, and a production casing. The process of drilling and then cementing progressively smaller strings of casing is repeated until the well has reached total depth. In some instances, the final string of casing is a liner, that is, a string of casing that is not tied back to the surface. The final string of casing, referred to as a production casing, is also typically cemented into place.
To prepare the wellbore for the production of hydrocarbon fluids, a string of tubing is run into the casing. The tubing becomes a string of production pipe through which hydrocarbon fluids may be lifted. Of interest herein, an annular region is formed between the production tubing and the surrounding casing string.
Some wellbores are completed primarily for the production of gas (or compressible hydrocarbon fluids), as opposed to oil. Other wellbores initially produce hydrocarbon liquids, but over time transition to the production of gases. In either of such wellbores, the formation will frequently produce fluids in both gas and liquid phases. Liquids may include water, oil and condensate.
At the beginning of production, the formation pressure is typically capable of driving the liquids with the gas up the wellbore and to the surface. Liquid fluids will travel up to the surface with the gas primarily in the form of entrained droplets. However, during the life of the well, the natural reservoir pressure will decrease as gases and liquids are removed from the formation.
As the natural downhole pressure of the well decreases, the gas velocity moving up the well drops below a so-called critical flow velocity. See G. Luan and S. He, A New Model for the Accurate Prediction of Liquid Loading in Low-Pressure Gas Wells, Journal of Canadian Petroleum Technology, p. 493 (November 2012) for a recent discussion of mathematical models used for determining a critical gas velocity in a wellbore. In addition, the hydrostatic head of fluids in the wellbore will work against the formation pressure and block the flow of in situ gas into the wellbore. The result is that formation pressure is no longer able, on its own, to produce fluids from the well in commercially viable quantities.
In response, various remedial measures have been taken by operators. For example, operators have sometimes sought to enhance the production of gas by replacing the original production tubing with a smaller-diameter string. A packer may be placed at a lower end of the new production sting to seal the annular area formed between the tubing and the surrounding strings of casing and to force the movement of gas to the surface through the smaller orifice. The smaller-diameter string creates a restricted flow path at the bottom of the wellbore, increasing pressure and aiding the flow of hydrocarbons to the surface.
A common technique for artificial lift in both oil and gas wells is the gas lift system. Gas lift refers to a process wherein a gas (typically methane, ethane, propane, nitrogen and related produced gas combinations) is injected into the wellbore downhole to reduce the density of the fluid column. Injection is done through so-called gas lift valves stacked vertically along the outside diameter of the production tubing. The injection of gas through the valves and into the production tubing decreases the backpressure against the formation. In some cases, a small dedicated tubing line is run down the annular region, clamped to the outer diameter of the production string.
In either instance, gas-lift systems have particular benefit for wells that have insufficient bottom hole pressure to support other forms of lift. Gas-lift wells are also used for producing deeper wells that have difficulty producing against a tall hydrostatic head. Still further, gas-lift systems do not suffer from gas interference problems caused by lighter hydrocarbons coming out of solution, as experienced with other forms of lift.
With the advent of the horizontal oil shale boom, gas lift systems have become increasingly useful as an artificial lift technique. This is primarily because of the ability of gas lift systems to manage entrained solids such as frac sand and scale. This is also because gas-lift wells do not experience the mechanical limitations that beam lift and electric submersible lift wells experience with non-vertical wells. Incidentally, gas lift is also popular for lifting oil wells in large fields or offshore facilities, as the power station may be remotely located from the wells.
In any instance, gas-lift systems rely upon compressors located at the surface that inject gas down the well annulus. When gas-lift systems became popular in the first half of the 20th century, injection (or reinjection) was provided from large central compressor stations having multiple banks, or stages, of compressors. Individual compressors were typically only designed to perform one stage of compression, meaning a series of compressors (or banks of compressors) were used to perform sequential stages of compression until the desired injection pressure was reached. Often, lean-oil “gas plants” were associated with these compressor stations, which would strip the propane, butane, hexane, and other components knows as natural gas liquids (or “NGL's”) from the gas prior to reinjection.
Compressor technology has improved in the last 60 years, with the advent of higher horsepower engines and compressor frames having smaller footprints. The large central compressor facilities have been replaced by smaller distributed compressor stations, with individual compressors capable of performing all stages of compression (usually three stages). However, the gas plant technology has not migrated to the field level due to economies of scale and the significant investment required. Stated another way, local compressors do not have an associated separator for stripping out NGL's.
It is observed that operators will install and use the same compressor for both their well-site injection as used for post-production gas sales. Beneficially, gas-lift compression and gas sale compression normally have the same discharge pressure requirements, that is, (1,000 to 1,200 psig). Thus, the well site compressor is physically capable of performing either task. However, design components favorable to “gas sales” work against the successful operation of a “gas-lift” compressor, primarily due to the NGL components that have not been removed due to the lack of an on-site gas plant. When NGL components go through the compression cycle, they often condense in the gas coolers. This causes multiple operating problems for the compression process, and results in additional expense, additional downtime, and sometimes environmentally un-friendly practices.
FIG. 1 presents a phase diagram 100 showing pressure (in PSIA) of natural gas as a function of temperature (in ° F.). Specifically, the natural gas is predominantly methane, with diminishing concentrations of ethane, propane and hexane. Trace amounts of carbon dioxide, nitrogen and sulfuric components may also be present.
As can be seen, at the lowest temperatures the natural gas mixture will reside in a fully liquid phase 110. Note that these are low, sub-zero temperatures. As temperature increases, the mixture will enter a two-phase condition 120 comprised of liquids and gases. The higher the pressure, the more liquids will be present. Finally, as the temperature increases, the mixture will enter a fully vapor phase 130.
For gas compressors, proper control of gas temperatures at elevated levels means keeping pressures and temperatures in the vapor phase 130. This will prevent condensation of any hydrocarbons and the attendant operational problems.
Accordingly, a compression system and method are needed that allow for the real-time control of discharge temperatures from compressors using on-site heat exchangers. A need further exists for a multi-stage compressor system for wellbore gas injection wherein the temperature control points of first and/or second stage cooler discharges are automatically controlled in order to push heat produced by adiabatic compression to the third (or a final) stage. Preferably, discharge temperatures throughout the compression process are elevated to maintain gas in the vapor phase.